Sinopec to Strengthen Investments in Upstream Assets

- Sinopec to Strengthen Investments in Upstream Assets

Monday, August 29, 2011
Dow Jones Newswires
HONG KONG
by Yvonne Lee

China Petroleum & Chemical Corp., or Sinopec, said Monday that it plans to strengthen investments in upstream oil and gas assets and unconventional resources over the next 5-10 years to further diversify its operations.

Chairman Fu Chengyu also said the company will accelerate the development of unconventional gas production, including shale gas and tight gas, in China and will disclose details of the development plan next year.

"We have 20 unconventional gas wells in China at the experimental stage. The output results are encouraging and better than expected," Fu said.

Shares of Sinopec ended up 6.7% at HK$7.49 Monday after Asia's largest refiner by capacity Sunday reported a better-than-expected 12% increase in first-half net profit to CNY41.17 billion from CNY36.80 billion a year earlier due to a stronger contribution from its oil production business, although its refining business recorded an operating loss due to rising fuel costs.

Fu said he is optimistic on the company's refining business prospects in the second half as crude prices will stay in a US $90-US $110 range.

However, he expects the global economy will be gloomy in the next 3-5 years if the U.S government launches a full-fledged third bond-buying program, commonly known as quantitative easing, or QE3.

"We hope to increase our cash level through the issuance of bonds to prepare any arising challenging," he said.

Sinopec said Sunday that it plans to raise up to CNY50 billion through the sale of domestic corporate bonds and the issuance of the convertible bonds in China.

Analysts expect Sinopec's refining margins to improve in the July-December period as crude prices eased recently, although the government price controls will still weigh.

"While the refining division is likely to continue to post a significant loss in the third quarter, we believe the second quarter was likely the peak for refining losses and the division could be close to break even in the fourth if Brent is around $107 or lower," Citigroup analyst Graham Cunningham said.

Copyright (c) 2011 Dow Jones & Company, Inc.

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Risk Is A Four Letter Word

- Risk Is A Four Letter Word

Thursday, August 18, 2011
Rigzone Staff
by Trey Cowan

The average investor often overlooks the simple concept of how the market discounts risk. Risk and reward typically correlate strongly with one another. Currently, the risk premium that an investor demands in exchange for lending to broader markets is expanding. In broad terms, investors must be anticipating that future risk levels are increasing.

To better define the risk/reward relationship, we first point to the current situation surrounding the 10-Year Treasury Note. From July through the week ending August 12, 2011, the note's yield has declined 26 percent from 3.18 percent to a 2.34 percent. Today, the 10-Year dropped below 2 percent.

Previously, the lowest the yield on the 10-year was 2.12 percent, set in December 2008; when fears regarding the global credit freeze were near their highest levels. Yields for fixed income instruments respond inversely to price. Investors buy the 10-Year to reallocate their holdings away from risk and into this safe-haven, which has the effect of driving the price up. We note the key concept in finance: the yield on a 10-Year is often looked upon as the proxy for the risk-free rate of return.

Another component in the valuation of assets is the risk premium. As the risk-free rate of return shrinks the average risk premium an investor demands must rise. In other words, if the 10-year yield is falling, then market risk is actually on the rise. Let's assume for a moment that an investor wants a 10 percent return on their investment. If the risk free rate has dropped from 3 percent to 2 percent, then the risk premium that investor is willing to take on has grown by a corresponding amount. Otherwise, the investor's required return falls to 9 percent (signifying their aversion to taking on additional risk). Therefore, when we see dramatic drops in the 10-year, like what just took place, all else equal, investment risks must be perceived to be on the rise. Such a move is justified to mathematically keep the overall return at equilibrium.

Using the earnings estimates we can prove that these financial concepts are factoring into current market valuations. For our example we are using the earning's yield of the the S&P 500 Index. We took the recent annual earnings for the S&P 500, $112.8, and divided it by the index value for the week ending August 12, 2011 (1178.81). What we found was that the earnings-to-price (E/P) yield was 9.5 percent. If you subtract the corresponding 10-year treasury yield (i.e. the risk-free rate) of 2.3 percent from the E/P, the remainder is the risk premium for the S&P 500 Index (i.e. 7.2 percent).

The risk premium for the S&P 500 is relevant for two issues. First, the S&P 500 includes only well-capitalized U.S. operated firms of a significant size. If the market expects a total earnings yield of 9.5 percent for blue-chip U.S. firms, then obviously the required return (and associated risk) for lesser quality investments is going to be higher. Second, the current risk premium at 7.3 percent for the S&P 500 is well outside the norm (3.85 percent average since 2005 and 5 percent YTD).

This growing level of inherent risk in the broader markets and the market's appetite for risk does have an impact on oil prices that is worth considering. Although the Fed's posture towards interest rates (and their vow to hold them low into 2013) would suggest that the dollar will remain weak, this is no time to get bullish on oil. Look no further than price variability to understand our reasoning. Since 2005, one standard deviation in the price of a barrel of oil represents 25 percent of the total price. Conversely, one standard deviation in the S&P 500 Index approximates 15 percent of the total. Therefore, at a time when the market is risk averse, an investment in crude oil bears with it 66 percent more risk than the total market.

Suppose that inherent in recent market sentiment is a fear that the U.S. economic growth profile for next year will slip by about 10 percent or approximately three-tenths of one percent of GDP. Ultimately, such a scenario would be accompanied by less demand for oil. We used regression analysis to compute the value of one barrel of oil based on a 10 percent decline in S&P 500 earnings using observations starting in 2005. Our calculations peg the implied value of WTI crude oil at $84/barrel based on if NTM earnings estimates drop $11 for the S&P 500 Index. Our calculations would be well below what the EIA and leading economist recently had considered a reasonable assumption for next year (+$100/bbl).

Also, consider how much the current risk premium exceeds its average 52-week value. Recent history suggests that a growing risk premium (that is well outside this 52-wk norm) spells trouble for oil prices. Back in 2008, risk premium exceeded its own norm by 2 percentage points. Oil prices in the subsequent 10 weeks fell 53 percent. Again in 2010, the S&P 500 risk premium broke 2 percent above its norm and oil prices fell 5 percent in the following ten weeks. With the markets now showing a risk premium that is again 2 percent above the norm, a repeat of this pattern does not seem far-fetched.

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State: Additional Cook Inlet Investments Could Find New Gas

- State: Additional Cook Inlet Investments Could Find New Gas

Monday, August 15, 2011
Alaska Journal of Commerce
by Tim Bradner

An investment of $1 billion to $2 billion by natural gas producers in additional drilling in gas fields in Southcentral Alaska could meet projected gas supply shortages in the region until 2018 or 2020, possibly eliminating the need for local utilities to import liquefied natural gas.

A recent study by the state Division of Oil and Gas shows that if producers drill eight new production wells per year in the four largest gas fields in Cook Inlet Basin, the fields will produce sufficient new gas to meet the current 90 million cubic feet per day demand in the region at a cost of $10 million to $20 million per well with an additional $100 million investment in compression.

"This study considers what we think it will take, in terms of revenue, to get producers to produce additional gas we believe is in these fields, although we can't say the price that the field operators will feel is acceptable to make the investment," said Joe Balash, deputy commissioner in the state Department of Natural Resources, in the briefing.

ConocoPhillips, Marathon Oil Co. and Chevron Corp. are operators at the four fields included in the study.

The region's utilities, however, are skeptical that investments by producers will actually be made, and are proceeding with plans to have imported LNG available in Cook Inlet within three years.

"We can't take a chance. Our estimates show a supply gas in the region as early as 2014," said Jim Posey, general manager of Anchorage's city-owned Municipal Power & Light, one of several utilities in negotiations with potential LNG suppliers.

Despite what the state study said, Cook Inlet producers are actually drilling about half the new wells needed to sustain current production levels, Posey said. Four new development wells are planned for 2011.

The study by the Division of Oil and Gas examines gas reserves the state believes remain in the four largest gas fields, which include the Beluga, Ninilchik, North Cook Inlet and the McArthur River Grayling gas sands based on data that is public and some that is confidential, and relies on known costs for drilling and compression.

Balash said the state study included only the large producing fields and did not include new gas found though exploration, such as a recent 10 billion-cubic-foot gas discovery made by Buccaneer Energy LLC, an independent, on the Kenai Peninsula.

The study indicates that producers could earn a 20 percent internal rate of return in 2018 at a gas price below $6 per thousand cubic feet (mcf), a price that is about what producers are selling most gas produced in Cook Inlet, and a 15 percent rate of return on a gas price below $5 per mcf.

However, another assessment made in the study is that the net present value of many of the investments in wells will be modest, which could discourage some companies, particularly larger companies, from exploring, Balash said.

"It's quite possible that smaller projects could have quite good rates of return and yet have small net present values. This kind of investment might be very attractive for a small independent and less attractive for a larger company," said Jeff Dykstra, a commercial analyst in the state oil and gas division and one of the authors of the gas study.

Independent companies are in fact showing much more interest in Cook Inlet than are large companies such as the current producers.

"Most companies use several financial indicators in assessing possible investments including rate or return and net present value as well as their cash-flow needs," Bill Barron, director of the state oil and gas division, said in the briefing. Whether an investment will be made depends on a company's internal investment threshold, Barron said.

Information in the study will be used by state legislators next year as they consider additional funds needed for planning a possible $7.9 billion, 24-inch gas pipeline that could be built by the state from the North Slope. The 24-inch pipeline, which could bring gas from the slope to southern Alaska by 2019, is being considered as an alternative if a large 48-inch Alaska gas pipeline is seriously delayed.

Balash said the division will do a second increment to its Cook Inlet gas study taking into consideration a new estimate of technically-recoverable gas resources released by the U.S. Geological Survey. The USGS estimated that Cook Inlet could hold as much as 19 trillion cubic feet of conventional and unconventional gas resources, more than twice the amount of conventional gas discovered so far.

"We will try to determine a minimum economic field size that would allow some of these new resources to be developed," Balash said.

Copyright (c) 2011, Alaska Journal of Commerce, Anchorage

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Shale Plays, Foreign Investments Drive U.S. Oil & Gas M&A Value

- Shale Plays, Foreign Investments Drive U.S. Oil & Gas M&A Value

Thursday, August 11, 2011
PwC

Ongoing interest in shale acreage, deals for midstream assets and increased investments from foreign buyers in the U.S. oil and gas industry helped drive U.S. oil and gas mergers and acquisitions (M&A) value to $39 billion in the second quarter of 2011, according to PwC US.

In the second quarter of 2011, there were 51 deals with values greater than $50 million, compared to 61 announced deals totaling $41 billion in the same period last year. While the volume and value of transactions dipped slightly in the second quarter of 2011 when compared to the same period last year, average deal value for deals over $50 million jumped to $765 million in the second quarter 2011, a 14 percent increase over the same period last year when average deal value was $672 million.

"There continues to be steady M&A activity in the oil and gas sector with strong competition for prized assets, which has maintained the deal momentum throughout the first half of the year. The second half of the year has already kicked off with one mega deal announced, and we expect that deal momentum to continue," said Rick Roberge, principal in PwC's energy M&A practice. "Foreign and private equity interest in North American oil and gas assets remains very high and will likely be a driver of ongoing activity."

Foreign buyers announced 18 deals valued at over $50 million or more in the second quarter of 2011, which contributed $36.2 billion or 72 percent of total deal value, versus 27 deals valued at $24.2 billion in the same period last year.

For deals valued at over $50 million, there were 11 midstream deals that accounted for $19.9 billion, or 51 percent of total deal value, compared to six deals worth $3.4 billion in the same period last year. Transactions in the upstream space led all oil and gas subsectors with 26 deals, or 51 percent of volume in the second quarter.

According to PwC, seven of the top 10 deals by value in the second quarter of 2011 were related to shale plays, including four upstream deals and three transactions in the midstream and oil field services space. For all deals greater than $50 million, there were 10 shale-related transactions totaling $7.5 billion, or 19 percent of total deal value, including two deals involving the Marcellus Shale totaling $2.3 billion.

"Shale-gas assets continue to be very attractive acquisition targets as multinationals look to gain technical know-how and exploit the long-term value and opportunities from rising energy needs," said Steve Haffner, a Pittsburgh-based partner with PwC's energy practice. "At the same time, there is tremendous activity developing around natural gas infrastructure, which is necessary to move the extracted gas to market. The U.S. 'shale gale' continues to attract the attention of global companies."

There were five financial sponsor-backed transactions over $50 million, representing $6.1 billion, or 16 percent of total deal value, compared to 10 financial sponsor deals contributing $6.2 billion during the same period last year. During the first six months of 2011, there were 16 financial sponsor deals contributing $20.6 billion, a whopping 129 percent increase in deal value, compared to the first half of 2010 when there were 15 financial sponsor-backed deals, valued at $9.0 billion.

"With oil prices hovering at $100, private equity funds continue to make a very strong push in the oil and gas sector," added Roberge. "The private equity deal makers, who used to largely play in the midstream space, are now heavily involved in exploration and production (E&P), shale plays, and oil field services and equipment sector. However, along with the great opportunities and rewards of investing in oil and gas, there is still risk in this space – and new entrants need to understand the pitfalls before trying to exploit these possible opportunities."

For deals with values greater than $50 million, there were 18 corporate transactions totaling $26.8 billion or 69 percent of total second quarter deal value, compared to 22 deals that accounted for $25.9 billion in deal value in the same period last year. Thirty-three asset deals for a combined total of $12.2 billion were announced in the second quarter of 2011, versus 39 deals totaling $15.1 billion in the same period last year. However, when comparing the first six months of 2011 to the first half of 2010, the number of corporate transactions increased by three deals to 35 transactions, while total corporate deal value jumped 26 percent to $59.7 billion in 2011 from $47.6 billion in 2010.

Another potential driver for M&A activity is the desire from some oil companies to sell assets and break apart key lines of business, according to PwC.

"We believe that another factor to keep a close eye on throughout the year, which may add to the already robust M&A activity we're seeing, is the trend of integrated oil companies looking at the various options to unlock shareholder value through separating their E&P businesses," said Roberge. "While this trend could be a very positive driver of M&A activity, these are highly complex transactions with potential consequences around tax considerations, valuations and financial reporting. Companies should consider the risk with these types of transactions as every potential scenario needs to be thoroughly and diligently evaluated to succeed."

PwC's Oil & Gas M&A analysis is a quarterly report of announced U.S. transactions with value greater than $50 million analyzed by PwC using transaction data from John S. Herold, Inc.

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Russia Plans to Boost Investments in Iraq's Oil, Energy Sectors

Russia Plans to Boost Investments in Iraq's Oil, Energy Sectors

Tuesday, May 10, 2011
Knight Ridder/Tribune Business News
by Nehal El-Sherif, dpa, Berlin

The Russian government was working to increase its investments in Iraq, especially in the oil and energy sectors, Russian Foreign Minister Sergey Lavrov said Tuesday.

"Russia supports the Iraqi government in its efforts to restore security and develop the economy," Lavrov said at a joint press conference with his Iraqi counterpart Hoshyar Zebari in Baghdad.

"We are also working to increase cooperation and our investments here ... We are delighted that Russian companies are working in Iraq in the energy field," he said.

A consortium led by Russia's private oil company, Lukoil, secured the rights to develop an oilfield in 2009. Lukoil recently announced plans to quadruple its oil production from the massive West Qurna oilfield, to the west of Basra. It said initial production was scheduled for 2012 and full production should begin in 2017.

Iraq has held three international bidding rounds since late 2009 to attract investments in its oil and gas industry.

It relies heavily on oil exports for its revenue and aims to raise production from 2.5 million barrels to 12 million barrels per day within six years.

Lavrov said they also discussed the security situation in Iraq and cooperation in the defense sector. He also said Russia intends to open a consulate in the southern city of Basra, where some of the largest oilfields are located.

Copyright (c) 2011, dpa, Berlin. Distributed by McClatchy-Tribune Information Services.

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RIL Tripled Investments in Group Companies in FY11

RIL Tripled Investments in Group Companies in FY11

Tuesday, May 10, 2011
Knight Ridder/Tribune Business News
by Aveek Datta, Mint, New Delhi

The Mukesh Ambani-controlled Reliance Industries Ltd (RIL) has used its strong cash flows to step up funding to new businesses such as shale gas and digital services, kicking off its next investment cycle.

RIL's 2010-11 annual report shows that the oil-to-yarn-to-retail conglomerate invested '7,593 crore in its subsidiaries and associate companies in fiscal 2011, almost three times the investment made in 2010. Net loans and advances given to these companies stood at '5,418.46 crore, against a receipt of '2820.43 crore from them in 2010.

Most of RIL's investments in subsidiaries and associate firms the last fiscal were driven by its fledgling shale gas operations in the US, a company official said. He did not want to be identified.

"We will augment our commitment to the Indian markets by investing in new petrochemical capacity, organized retailing and digital services," Ambani said in his letter to shareholders.

Overall, the company in 2011 made investments worth '37,651.54 crore, 62% higher than in 2010. This included a '5,897 crore investment in various mutual funds.

RIL put '2,207.70 crore in a wholly owned subsidiary, Reliance Exploration and Production Mauritius Ltd--the vehicle through which RIL holds its stakes in the three shale gas joint ventures in the US. "The investments comprise part payments that we were required to make upfront payments as well as guarantees for the deferred payments," the official said.

The increase in loans and advances are also mostly linked to the firm's shale gas venture as they have been used to make the equity payments.

RIL recorded an around 10-fold increase in the financial guarantees that it extended on behalf of associates and subsidiaries, at '21,637.59 crore. Apart from guaranteeing deferred payments for its shale gas partnerships, the company has also furnished guarantees against future cash calls to be made by the joint venture partners of its wholly owned subsidiary Reliance Holding USA Inc. to the tune of '9,409.55 crore, RIL's annual report said. Reliance Holding USA had issued bonds worth $1.5 billion ('6,705 crore today) in October.

In a span of five months till August, RIL acquired three shale gas assets in the US for a total consideration of around $3.44 billion.

"The JVs (joint ventures) are expected to accrue resources in excess of 10 tcfe (trillion cu. ft equivalent of gas) and make a meaningful contribution to our earnings within the next few years," Mukesh Ambani told RIL shareholders.

According to analysts, with the kind of cash flow that RIL is expected to generate, high levels of investment are likely in the coming quarters as well.

Reliance may have as much as $22 billion in cash and cash equivalents by 2012, including payments from BP Plc and an estimated cash profit of $8 billion in the next fiscal year, according to a 22 February report by HSBC Securities and Capital Markets (India) Pvt. Ltd.

RIL had said during the announcement of its January-March quarter financial results that it had already received an initial $2 billion from BP, which is being treated as a current liability pending regulatory approval to the deal.

"RIL will continue to show high investment figures as it has entered a number of new ventures," said S.P. Tulsian, a Mumbai-based independent stock market analyst. "In shale gas, RIL might reach the maximum level of investment in three to four years, while for broadband it should happen in 24 months."

Some brokerages, however, remain sceptical about RIL's ability to deploy the cash its operations have generated.

"(RIL's) management acknowledged that utilization of cash remained a key challenge," a 22 April Citigroup Global Markets Inc. report stated.

"While RIL had already decided to use a part of this (cash) for pursuing organic growth opportunities...management reiterated that a part of this would be used for inorganic opportunities as well," Citi analysts Saurabh Handa and Graham Cunningham noted.

During the last fiscal, RIL also made a major investment of '4,155.99 crore in Infotel Broadband Services Ltd, the pan-India winner of broadband wireless spectrum that it acquired in June, marking the conglomerate's re-entry into telecom.

Interestingly, RIL did not make any new equity investment in its retail ventures. RIL's investment in the equity shares of Reliance Retail Ltd as on 31 March was '5,220 crore, the same as at the end of fiscal 2010.

Tulsian said RIL's retail arms did not receive any fund infusion as either the firm was going slow on retail expansion or they may have started generating enough cash on their own and could have even achieved cash break-even, though they reported net losses for the last fiscal.

After reaping the benefits of its last value creation cycle in 2009-10 by redeeming investments in subsidiaries and associates to yield '6,482.55 crore, there was negligible sale of similar investments 2011.

Over the last fiscal, RIL's shares have underperformed the broader market. Share prices of RIL lost 2.5% in 2010-11, while the benchmark equity index of the Bombay Stock Exchange, Sensex, gained 10.94%.

On Monday, RIL's share price gained 0.31% to close at '958.35 per share, while the Sensex rose 0.05% to close at 18,528.96 points.

Copyright (c) 2011, Mint, New Delhi. Distributed by McClatchy-Tribune Information Services.

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Oil Cos Tell Legislature Investments Lost Due to Taxes

Oil Cos Tell Legislature Investments Lost Due to Taxes

Monday, April 04, 2011
Alaska Journal of Commerce

by  Tim Bradner

 

Major employers in the state, worried about the future and whether there will be enough oil to operate the Trans-Alaska Pipeline System, are pressing legislators to reduce Alaska's high petroleum taxes to encourage new investment and oil development.

In several days of hearings before the House Finance Committee the week of March 28, companies told of sharp reductions in work that has caused them to lay off workers.

Meanwhile, oil companies -- large firms and small independents -- have painted a bright future for the state's petroleum industry if the Legislature acts to approve Gov. Sean Parnell's bill to adjust the tax, or something like it.

"Let's change the sound bites. Instead of talking about giving up $2 billion, let's talk about stabilizing the decline in production," Ken Thompson, managing partner of an Alaska-based independent exploration company, told legislators.

Thompson's company, Alaska Venture Capital Group, one of the owners of Brooks Range Petroleum Co., is just the kind of independent company legislators want to encourage. Brooks Range Petroleum is drilling the lone exploration well being done this winter on the North Slope.

Thompson said the investment tax credit portion of the state production tax does help small exploration companies like his, but the overall tax rate, which goes higher as oil prices climb, is making it tough to raise capital from investors.

Thompson's group lost one big investor for its exploration program because other places are more attractive than Alaska, he told the House Finance Committee in hearings.

However, if the tax rate were lowered, independents could ramp up exploration. Brooks Range Petroleum could put a second drill rig to work, and perhaps a third, Thompson said.

Bart Armfield, operations vice president at Brooks Range, believes independent explorers, with the right tax environment, would find enough new oil deposits, even if small ones, to flatten the oil decline.

There are plenty of prospects for small companies, Thompson said. "For small independents discoveries of 10 million, 25 million or 50 million barrels are just fine," he said.

Armfield said Brooks Range's owners, a group of small, mostly family-owned independents as well as Alaska investors like Thompson, previously had their core areas in places like Kansas. A few years ago, growth prospects at home were small for these companies, Armfield said.

Alaska was attractive because there were larger prospects, even if these were too small to interest the larger companies. However, higher state taxes have dampened Alaska's assure. Had companies known ACES was coming, they probably wouldn't have invested, Armfield said.

Independents priced out

High oil prices have hurt Alaska's competitiveness in the eyes of many potential independent investors.

"Now oil is at $100 a barrel and there are a lot of opportunities close to home in areas these people know and where they are comfortable," Armfield said. "HB 110 would make positive changes, however."

Great Bear Petroleum, an Austin, Texas-based independent that wants to experiment in drilling and producing from shale rocks on the North Slope, said it sees bright potential.

"We have an aggressive program that supports 250 wells per year for 20 years starting in 2013," the company's chief financial officer, Ryan Moynagh, told the finance committee.

If the idea pans out, about 150,000 barrels day, and perhaps more, could be produced from shale.

However, Great Bear must still test its concept that oil can be economically produced from shale rock on the Slope. The company has two exploration wells planned for next winter, and must still raise the investment capital needed for development. Improving the tax environment would help Great Bear, Moynagh told the finance committee.

"The easy conventional oil has been found. There is remaining large volume potential in unconventional plays, such as heavy oil, shale oil and gas," Moynagh said.

But costs rise on a per-barrel basis and the economic return will decline due to field sizes getting smaller, a challenging, high-cost operating environment, exploration becoming riskier and new exploration initiatives like heavy oil and oil and gas shale being expensive, he said.

"Discovery and development of Alaska's remaining potential would be significantly enhanced by improvements in Alaska's fiscal terms, such as those in House Bill 110," Moynagh said.

Support wanes

Alaska firms engaged in oil support work are more discouraged, however. Margie Brown, president of Cook Inlet Region Inc., told legislators she is worried about a political environment in Alaska that seems to chill private investment.

"We're seeing a lot of resistance to private investment to the point that even we are beginning to look for more investment opportunities outside Alaska. Capital moves to places with less risk, and I don't want to see that happen to Alaska," Brown told the House Finance Committee.

CIRI owns oil and gas producing properties in Southcentral Alaska and has a big stake in North Slope contractor companies.

"We've seen a dramatic decline in our Slope work. The magnitude of the decline is alarming," Brown said. "The status quo is not an option, and we're concerned about this talk of 'giving away' money to the oil companies. We do support the governor's efforts. His legislation is on the right track."

Ethan Schutt, CIRI's vice president for land and energy, said he was infuriated coming through Calgary recently and seeing the bustle of drilling and activity and the coming home to learn that the liquefied natural gas plant near Kenai is being shut down and the Agrium fertilizer plant next door, already closed, may be broken up and shipped to Nigeria.

Aaron Schutt, vice president for operations at Doyon, Ltd., echoed the comments by Thompson and Armfield. (Ethan and Aaron Schutt are brothers.) Schutt said his company, which is exploring Interior Alaska basins, lost an industry partner in exploring the Nenana Basin and has been unable to find a partners in the Yukon Flats basins, both areas with prospective geology but also high risks. Lacking an industry partner Doyon is leading these exploration efforts itself, so far.

"The exploration tax credits helps explorers at the front end, but these companies (the prospective partners) look at the life cycle of the project, which includes the tax," Schutt told legislators.

There have been small companies coming in to explore, but what's really needed are larger companies with the financial strength to put discoveries in production, and these are lacking, Schutt said.

Doyon is heavily invested in North Slope support work, with has three quarters of its corporate capital tied in a fleet of six drill rigs operated by subsidiary Doyon Drilling. About 1,400 people are employed in the Doyon's oil-related service companies, including 435 Doyon shareholders. A full 90 percent of Doyon's oil workers are Alaska residents, Schutt said.

Tara Sweeney, senior vice president of Arctic Slope Regional Corp., urged legislators to reform the state tax law.

"Oil and gas is the bedrock of our economy. It is directly one-third of the economy and it provides 90 percent of state revenues," Sweeney said.

The current tax is double and triple the petroleum tax rates of producing states like Wyoming and North Dakota, she said.

Arctic Slope employs 4,000 in Alaska, mostly in energy-related businesses, she said. ASRC Energy Services, an oil services subsidiary, is one of the state's largest employers. Petro Star, a refining subsidiary, markets fuel products.

ASRC also receives royalties from oil production from subsurface rights it owns in the Alpine field and has invested with other companies in exploration on the North Slope and in Interior Alaska. ASRC is now a partner with Savant Resources in the restarted Badami field, a small field east of Prudhoe Bay.

The corporation has been working to get investors interested in North Slope projects but has been unsuccessful so far, and the state tax is at least partly to blame, Sweeney said.

"The lost opportunities are just devastating. What we have now is not working," she said.

Major North Slope oil operators could not guarantee new investments would come if the tax is lowered but they said it is highly likely.

"My expectation is that if House Bill 110 passes, we will spend more money in production-enhancing activity, all aimed at getting more production into the pipeline," Claire Fitzpatrick, chief financial officer for BP Exploration Alaska, told the House committee. "We would be using our existing fleet of drill rigs to the maximum and perhaps bring on another rig. If we add another rig that's a hundred jobs."

Fitzpatrick said two major west Prudhoe Bay development projects that were stalled when the Legislature raised taxes in 2007, a gas partial-processing plant and a new drill pad, with 50 new wells, would very likely proceed if the tax were adjusted.

"This would add a significant amount of work. It would have a big effect on contractors," Fitzpatrick said.

Wendy King, ConocoPhillips' external affairs vice president, told legislators that Alaska has the highest oil production decline rate of any state in the nation, 36 percent since 2003.

In contrast, Texas has only declined about 1 percent and production is growing in many states. In North Dakota, Utah and Mississippi, production is up 30 percent, King said. 

UK Oil Producers to Lobby Osborne Over North Sea Tax Hike

UK Oil Producers to Lobby Osborne Over North Sea Tax Hike

Thursday, March 31, 2011
Dow Jones Newswires

by  James Herron & Alexis Flynn 

Major U.K. oil and gas producers said Thursday they will directly lobby Chancellor of the Exchequer George Osborne to mitigate the effects of a large tax increase on the industry, after a meeting with the energy minister and other senior government officials failed to allay their concerns.

The move comes as several large companies said they were reconsidering billions of pounds of investments in oil and gas production after last week's shock tax increase, and as the government published figures showing that U.K. oil and gas import dependence grew significantly last year.

Earlier Thursday, industry group Oil & Gas U.K. met Energy Secretary Chris Huhne to raise its concerns about the country's new tax regime, which it argues will hinder investment and result in job losses. Chancellor of The Exchequer George Osborne last week announced a GBP2 billion tax increase on oil production in the government's latest annual budget.

Several producers have already voiced their concerns at the decision, with Norway's Statoil and France's Total both saying they would re-appraise their investment plans in light of the news.

Of particular concern to companies affected by the tax rise is whether the government will stand by its stated commitment to lower the tax on producers if the price of oil made a "sustained" drop to around $75 a barrel, said one person at a U.K. oil producer.

U.K. North Sea explorers and producers are "seeking a lot of clarity on this floor price of $75 and want assurances that this genuinely will be implemented," the person told Dow Jones Newswires Thursday.

"I don't think there's a great deal of confidence at the moment that that is written in stone," said the person, who asked not to be identified.

Oil and Gas UK said Wednesday the "sudden and destabilizing" nature of the tax increase meant it was likely more companies would follow Statoil's lead.

The strong industry reaction was partly due to the surprise nature of the announcement, the person said.

The oil and gas industry is a "long-term business that prides itself on risk management, on planning. It's not very good at dealing with surprises," he said. "At some point things will settle down, but it isn't going to happen soon."

Scottish lawmakers lambasted the government's failure to consult on the issue.
First Minister Alex Salmond, whose Gordon constituency includes Aberdeen, the capital of the U.K. oil and gas industry, said the government should have met with firms before the announcement.

"Furthermore, the tax changes announced by the chancellor are totally ill-thought through and run the risk of diverting investment away from the North Sea," Salmond said. "There is nothing wrong with making taxation responsive to profitability and high oil prices, however it has to be done in a planned fashion with appropriate incentives for marginal fields and infrastructure development in order to avoid the impact on Scottish jobs which the chancellor's spatchcock and desperate moves now put at risk."

Brazil OGX Plans Investments of $2B in 2011 -CFO

Brazil OGX Plans Investments of $2B in 2011 -CFO

Monday, March 28, 2011
Dow Jones Newswires

by  Jeff Fick

 

OGX expects to invest about $2 billion in 2011 as it ramps up exploration efforts and produces its first oil, the company's chief financial officer said Monday.

"This will be for drilling exploratory wells and production at the extended-well test," CFO Marcelo Torres said during a conference call with analysts. The independent driller, which is still in the pre-operational phase, expects to produce its first oil from an extended-well test at the Waimea prospect in the third quarter.

Part of the 2011 capital expenditure budget will be directed at pioneer wells in the Para-Maranhao Basin, said Chief Executive Officer Paulo Mendonca. The company expects regulators to issue a license to start drilling OGX's first wells in the basin in "two weeks," Mendonca said. The drilling platform hired to spud the wells is on site and ready to start work once the license is approved, the executive added.

In the Espirito Santo Basin, meanwhile, OGX is focused on post-salt prospects, Mendonca said. While Brazil's much-ballyhooed pre-salt region extends into the basin, the depth of the pre-salt targets puts them out of OGX's reach at the moment.

"We have to do 3D seismic, but the locations we are looking at are in the post-salt. Maybe in the future it will be possible to think about pre-salt," Mendonca said. The executive noted that pre-salt targets in the region were at about 10,000 meters deep, a depth at which OGX is not yet authorized to drill.

"In the future, perhaps, we can find something not so deep," he said.

Late Friday, OGX reported a fourth-quarter 2010 loss of 123.4 million Brazilian reais ($74.3 million), compared with a loss of BRL100.6 million a year earlier. OGX is still in a pre-operational phase and reported only financial earnings from cash on hand. OGX said it holds BRL4.8 billion in cash.

Analysis: Potential Exists for Small Scale LNG Production in Southeast Asia

Analysis: Potential Exists for Small Scale LNG Production in Southeast Asia

Thursday, March 24, 2011

Rigzone Staff

by  Karen Boman

Investments in infrastructure for small scale liquefied natural gas (LNG) power production might be justified when the total demand for electric power exceeds 500 MW within a 120,000 square kilometers island region with no pipeline connection, according to a joint industry project (JIP) on the future small scale LNG value-chain in Southeast Asia.

Classification society Det Norske Veritas (DNV) reported that the study, which examined two areas of future LNG use in Southeast Asia, also identified noteworthy potential for LNG as a fuel for ships in regional trade, and predicts a future market for LNG bunkering in Singapore.

"Substantial market opportunities will evolve throughout the small scale LNG value-chain in Southeast Asia in the next decade," said managing director Bjorn Tore Markussen of DNV's Clean Technology Centre in Singapore, who has also headed up the JIP. "The companies who seize the opportunities early in these evolving markets will be well positioned for interesting growth if entry risks are managed properly."

The study identified multiple island regions in Southeast Asia outside any pipeline grid where total demand for electrical power exceeds 500 MW. Based on a number of underlying parameters and assumptions, various financially feasible scenarios were modeled. For example, Eastern Indonesia might have a demand for up to 70 small scale 50 MW power plants by 2020. Equally, Southern Philippines could require up to 45 plants, while the estimated demand for Northern Vietnam might be seven small power plants.

The distribution of LNG to these power plants would require close to 60 small scale LNG carriers by 2020 if this number of plants is built. As the price of crude oil is rising faster than the price of natural gas, the financial incentives for using LNG for power generation are equally increasing with considerable environmental benefits to be gained from such a fuel switch.

Shipping is a vital part of the future LNG supply chains in Southeast Asia, DNV noted. The study forecasts that container feeders might be the first ship segment to adopt LNG for propulsion regionally. About 20 % of the regional container feeders are up for renewal by 2020. Local and regional ferries are also well suited to use LNG for propulsion in the longer term.
Singapore is identified as the regionally preferred site for future LNG bunkering, due to large shipping volumes, calm seas for bunkering operations and the fact that infrastructure for LNG bunkering is already under construction. With stricter requirements for environmental performance, and an increasingly competitive expected price for LNG as fuel for ships, a shift to LNG propulsion may have an exciting impact on Singapore as a bunkering hub.

Lam Yi Young, chief executive of the Maritime and Port Authority of Singapore (MPA), said, "With the push towards cleaner fuel for ships, the results of this Joint Industry Project are timely in evaluating the potential for LNG bunkering services in Singapore. LNG's lower carbon dioxide emissions, minimal sulfur and nitrogen content as well as the abundant availability, allows it to be a viable alternative fuel source for ships, which is also in line with MPA's commitment to promoting environmentally-friendly shipping."
"The consortium is eager to use the findings from the LNG study to build business for the participants and to inform regional stakeholders about the opportunities that lie ahead," said Markussen, "DNV as a company has already decided to invest into a next phase of the JIP. We are now inviting old and new members to join the consortium and one or more of the many project streams that will be kicked off in April and May."

The JIP, which was initiated by DNV during Singapore Maritime Week in 2010, included a consortium of 16 participants from all parts of the LNG value chain, including Gazprom, Rolls-Royce, Wartsila, Hanjin Shipping, I.M. Skaugen, Keppel, The Linde Group, Trans LNG, DNV, BW group, BBG, the Maritime and Port Authority of Singapore, and the two Singapore universities NUS and NTU. The JIP is also supported by Innovation Norway and The Norwegian Embassy in Singapore.

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